Enhanced oil recovery (EOR) which was industrialized particularly in the United States between 1973, the date of the first oil crisis, and 1986, the date of the oil price collapse to 10 dollars a barrel, was put back on the agenda at the beginning of the 2000s decade when the price of oil exceeded 40 dollars a barrel. With a current cost of 100 dollars a barrel, enhanced oil recovery with the use of water-soluble polymers, which permits an additional 10% to 20% increase of the yield of the reserves in place, has become a choice technique.
However, its use in large oilfields comes up against certain technical problems which are gradually being solved.
One of the device that has enabled this development is the PSU (Polymer Slicing Unit) described in patent EP 2 203 245. These types of water-soluble polymers are very difficult to disperse due to a bonding and agglomerating effect that gives gels or “fish eyes” that take a long time to dissolve. These gels cannot be injected into the formations without damage. The PSU enables both an excellent dispersion and a high dissolution concentration reducing the sizes of the dissolution tanks and high-pressure pumps which constitute a significant part of the investments needed.
The second problem is the mechanical degradation of the polymer. Customarily, on an oilfield, a single water injection pump supplies several wells. But due to the heterogeneity of the fields, the injection pressures are different from one well to the next. For this, a control or pressure-regulating valve known as a choke is installed at the wellheads. The polymer solution cannot pass through this choke without a degradation that is practically proportional to the pressure drop. Roughly, a pressure drop of 20 bar will degrade the viscosity by the order of 20%. A pressure drop of 50 bar will degrade the viscosity by the order of 50%. Obviously, these degradations are dependent on the type of polymer, on the viscosity, on the concentration of the dissolution brine composition and on the temperature. Only pilot tests make it possible to predict the amplitude of the degradation.
In order to overcome this problem, various solutions have been used:                Customarily, the stock solution prepared at a concentration of 10 to 20 g/liter is pumped by a high-pressure triplex pump at the wellhead, after the choke, before a static mixer. This system requires numerous pumps (one per well) and numerous pipelines, which increases the cost of the installation.        Another solution is to create a solution at the final concentration (500 to 3000 ppm) and to inject it into each well by means of a linear pressure reducer as described in U.S. Pat. No. 8,607,869.        
This linear pressure reducer is modular and makes it possible, using 3 to 6 lengths of tubes separated by 4-way valves, to regulate the pressure with an accuracy of 1 to 5 bar, it being possible to carry this out manually or by means of a programmable controller. It is in the form of a housing where the stainless steel tube windings may be activated or deactivated in order to obtain the required pressure.
From a technical point of view, the flow of a polymer solution in a tube does not cause any degradation or causes very little degradation of the polymer up to a certain speed that is dependent on the diameter of the tube, on the viscosity, on the salinity of the solution and which can be determined experimentally.
The pressure drop changes as a function of the flow speed of the polymer solution in the tube, and as a function of the flow rate as shown in FIGS. 1 and 2. In other words, the polymer is degraded to a greater or lesser extent as a function of the flow speed as shown in FIG. 3.
Customarily, the degradation depends on the speed and on the diameter of the tube. It is considered that a pressure drop of 1 bar over 10 meters leads to an acceptable degradation. However, due to the composition of the brine, the type and concentration of the polymer, and the temperature, prior tests make it possible to optimize the diameter and the length of the tube constituting a linear choke.
In the case mentioned in FIGS. 1 to 3, and for a given diameter of 1 inch, in order for the pressure drop to be less than or equal to 1 bar over 10 meters, the flow speed should not exceed 7.5 m/s approximately, and the flow rate should not exceed 13 m3/h.
Customarily, standard chokes make it possible to control the pressure over a pressure drop range from 0 to 50 bar, which corresponds to the use of a linear pressure reducer of 500 meters approximately.
A linear pressure reducer as described in U.S. Pat. No. 8,607,869 functions very well when it is used at the surface since it is directly accessible for inspection and maintenance operations. The liquid, electric or hydraulic connections become extremely important when a high degree of reliability is required.
But this type of apparatus becomes very complex when it is desired to adapt it to subsea applications, in particular as regards the replacement of valves, of coils, of measurement apparatus, the inspection of the valve openings, the connections to the surface and the high maintenance, depending on the case, by divers or robots.
Extrapolated to a subsea installation, this type of apparatus leads to additional constraints inherent to its technology (control and measuring devices, confirmation of the openings of the valves, measurement of flow rate and pressure, modules that can be disconnected for maintenance, electrical housings, umbilicals, etc.).